Understanding Transformer Connections and Phase Shift

Have you ever tried to coordinate feeder relays with the substation transformer overcurrent elements and felt the math didn’t quite line up? It happens because the current seen on the transformer high side is not the same as what the feeder relays measure on the low side. The transformer’s turns ratio and winding configuration reshape the fault current before it reaches the high-side device. Here’s the step-by-step logic I personally use when checking coordination: 1) Understand the transformer connection A common North American distribution substation transformer is high side Delta / low side Yg. Don't forget: the Delta blocks zero sequence current from passing to the high side. 2) Know what each relay is measuring • Low-side feeder relays (phase/ground) measure positive, negative, and zero sequence current on the low-voltage base. • High-side phase overcurrent sees only positive and negative sequence current for a low-side line-to-ground fault because the delta traps I0. 3) Compare currents for the same fault For a single-line-to-ground fault on the feeder: • Feeder current: I(feeder) = I1 + I2 + I0 • High-side current: I(high side) = I1 + I2 • The feeder device responds to the full residual current, while the transformer protection is blind to I0. 4) Identify the tightest point of coordination Surprisingly, it’s not the LG fault. The toughest case is a LL fault near the substation: • Feeder side 50/51P sees about 87 % of the current it would see for a 3ϕ fault. • High-side transformer 50/51P sees nearly the full 3ϕ current because the delta winding passes positive and negative sequence unchanged. If you coordinate the feeder phase time-overcurrent 50/51P pickup and curve to clear before the high-side 50/51P for this LL case, you’ll generally maintain margin for all other fault types (including LG and 3ϕ faults). 5) Verify with actual curves Time-current curves on the low-side feeder relays and the high-side transformer protection must be compared using the converted current magnitudes each will experience. Only then can you be sure the feeder clears before the transformer trips for downstream faults. Real systems complicate this: zero-sequence compensation on feeder relays, different CT ratios, and relay curve shapes can all shift coordination. Questions for the community: • Have you seen feeders miscoordinate because someone forgot the delta blocks zero sequence? • Any lessons from real faults where the high-side transformer protection tripped first? I’d like to hear how others are refining these checks with today’s digital relays and modeling tools (ASPEN Inc., CYME, ETAP Software, EasyPower Software, SKM, etc). Comment or share your experience (or share this post if you found it valuable)!

When is the impedance or admittance from point A to point B different from point B to point A? This is somewhat interesting, as I don't think many people delve into it, and the examples in textbooks often don't stray far enough to get into the details.  Like I said yesterday,  the admittance matrice (phase, positive, negative, and zero sequence) basically consists of two types of terms.  Bus-to-bus admittance paths (i to j and j to i) and self-admittance (ii and jj) entries in the matrices.  The negative and zero sequence matrices tend to be very similar due to most of the impedance on the grid being passive, the positive and negative sequence impedances being the same.  The ground matrices and the shunt terms are ground sources and the non-diagonal (i,j) terms are series zero sequence impedances. That all sounds kind of straight forward and it can be. So, how are transformer phase shifts modeled? This is where things get a little complicated.  When current passes over an inductor or capacitor (series), it will phase shift the current and this results in the voltage drop amongst another element along the path to be shifted.  The problem with this is that this relationship is the same each way down the line.  This is not how transformers phase shift voltages and currents.  For example, a Dy1 transformer's 1-hour code means that the LV side lags the high side by 1 hour or 30 degrees. Likewise, a Dy11 would mean that the LV side leads the HV side by 30 degrees or lags by 330 deg.  The problem here is that this relationship is not symmetrical, HV to LV is always different from LV to HV for hour codes not 0 or 6. This analysis is also done in per-unit so the turns ratio elements drop out. This means that in the admittance matrices, the Y(i,j) admittance has to be different than the Y(j, i) admittance so that the phase shift relationship appears the same way if you are comparing current flows in either direction.  And this is how it is done.  Y(i,j) is divided by a phase shift 'a1' = 1<30 deg x hours, and Y(j, i) is divided by the complex conjugate of 'a1', 'a1*'.  The complex conjugate is like the reflection of the phasor or vector over the real x-axis). conjugate((a+ j b)) = (a - j b).  The result of this is that the phase shift of the voltages and currents is consistent no matter the direction of the current flow. If the relationship wasn't like this, you couldn't have asymmetrical phase shifts, anything not 0 or 6 hours, between the HV and LV windings. The reason why this is interesting to me is this is one of those times where the admittance and the impedance are not the same between point A and point B as point B to point A.  #utilities #substation #electricalengineering #renewables #energystorage

Welcome to the Knowledge Daily Series Power Systems Simplified: Part 1/5 ⚡ Understanding the Vector Group of Transformers The Vector Group of a transformer is a key specification that defines its phase difference and wiring arrangement. In this first part of the Power Systems series, we’ll explore the basics and practical applications of Vector Groups. --- What is a Vector Group? The Vector Group indicates: 1. Phase Displacement: The angular difference between the primary and secondary windings. 2. Winding Configuration: Whether the windings are delta (Δ) or star (Y). Example: Dyn11 D: Delta-connected primary winding. y: Star-connected secondary winding. n: Neutral point brought out on the star side. 11: 30° phase shift (clock system). --- Why is the Vector Group Important? 1. System Compatibility: Ensures transformers can operate in parallel without phase conflicts. 2. Load Sharing: Proper configuration avoids circulating currents. 3. Fault Isolation: Determines how the transformer handles unbalanced loads and faults. --- Common Vector Groups and Their Applications 1. Dyn11 Application: Distribution transformers in power networks. Benefit: Handles unbalanced loads well. 2. Yyn0 Application: Small-scale systems. Benefit: Zero phase shift simplifies integration. 3. Dd0 Application: Industrial setups. Benefit: No neutral, reducing fault risks. 4. Yd1 Application: Step-down transformers. Benefit: Suitable for connecting high and low-voltage systems. --- How to Identify the Vector Group? 1. Test Setup: Apply a small voltage to the primary winding and measure the secondary side. 2. Clock Method: Use the clock face analogy where 12 represents no phase shift. Dyn11 means the secondary leads the primary by 30° (11 o'clock). --- Practical Example Imagine a grid connection with two transformers: T1: Dyn11 T2: Dyn1 If connected in parallel, the 60° phase difference can cause circulating currents, leading to losses and instability. Ensuring a compatible Vector Group is critical. --- Conclusion Understanding Vector Groups is essential for designing and maintaining efficient power systems. It ensures transformers work seamlessly, reduces faults, and optimizes performance. Stay tuned for Part 2/5, where we’ll dive into Grid Failure: Causes and Prevention. #Transformers #PowerSystems #EngineeringBasics #9AM9